METHODS FOR TREATMENT OF A SUBTERRANEAN FORMATION

Abstract

The present disclosure relates the methods of treating a subterranean formation. In various embodiments, an acidic treatment fluid can be injected through tubing while a non-acidic fluid is pumped through an annulus. In various embodiments, acidic treatment fluid can be pumped through coiled tubing while at least one of acidic treatment fluid and non-acidic fluid are pumped through a second tube surrounding the coiled tubing and an annulus disposed the second tube and a borehole. Various embodiments also include methods for stimulating a well and acidization of the subterranean formation.

Description

BACKGROUND OF THE INVENTION

Well stimulation is performed on a subterranean formation to increase or restore production. For example, a well that exhibits low permeability can be stimulated to instigate production from a reservoir. Further, well stimulation can be used to restore near-wellbore permeability and enhance flow from an already existing well that has become under-productive or even unproductive.

Well stimulation can include acidization, such as matrix acidizing and fracture acidizing. Acidization attempts to increase or restore production of the subterranean formation. Matrix acidization can include pumping acid into the well below a fracture pressure and into pores of a subterranean formation, such that the acid can dissolve sediments or mud solids inhibiting permeability of the subterranean formation. Fracture acidizing can entail pumping acid into a naturally- or hydraulically-fractured formation such that the acid will dissolve the formation, enhancing productivity, wherein acid creates etching pattern by dissolving rock inside the fracture that provides increased conductivity for hydrocarbon flow.

SUMMARY OF THE INVENTION

In various embodiments, the present invention provides a method of treating a subterranean formation. The method can include injecting a treatment fluid, comprising at least one of acid and solvent, through a first passage while at least partially simultaneously injecting a non-acidic fluid through a second passage. The method can further include contacting a mixture of at least the treatment fluid and the non-acidic fluid with a subterranean material downhole. The first passage can comprise tubing disposed in a casing or borehole, wherein the second passage can comprise a space between the tubing and the casing or borehole.

In various embodiments, the present invention provides a method of stimulating a well. The method can include injecting a first non-acidic fluid through a first passage comprising tubing. The method can include reducing the injecting of the first non-acidic fluid through the first passage. The method can include injecting a second non-acidic fluid through a second passage comprising a space between the tubing and a borehole or casing. The injecting of the first non-acidic fluid through the first passage can be stopped, while, at least partially simultaneously, acidic treatment fluid can be injected through the first passage. The method can further include subsequent comingling or foaming the acidic treatment fluid of the first passage and the second non-acidic fluid of the second passage at a downhole location in the borehole. A concentration of the acidic treatment fluid in the comingled fluids can be varied or the comingled fluid can contact a subterranean material of the well.

In various embodiments, the present invention provides a method of acidization of a subterranean formation. The method can include injecting a first non-acidic fluid through a tube disposed in a borehole. The injecting of the first non-acidic fluid through the first passage can be reduced, while at least partially simultaneously injecting a second non-acidic fluid through an annulus disposed between the tubing and a borehole or casing. The method can further include stopping the injecting of the first non-acidic fluid through the first passage, while at least partially simultaneously injecting an acidic treatment fluid through the first passage. The method can include comingling the second non-acidic fluid and the acidic treatment fluid at a first downhole location. The comingled fluid can contact the subterranean formation downhole. The method can further include increasing at least one of the concentration or an injection rate of the acidic treatment fluid upon detecting acidization, increased fluid leak off, or both. At least a portion of a spent fluid can be pumped from a second downhole location to a surface.

Various embodiments of the present invention have certain advantages over other methods for treating subterranean formations, at least some of which are unexpected. Various embodiments of the present invention provide methods for stimulating or enhancing stimulation of a subterranean formation or well, and thus can improve the acidization treatment or the production performance of the well. Certain embodiments of the present invention permit variable control of the concentration of acid in acidization fluid downhole. For example, the concentration of acid in the commingled acidization fluid downhole can be altered relatively rapidly, as compared to previous acidization techniques that alter acidization fluid acid concentration at a surface prior to injecting downhole. Such embodiments can provide the benefit of controlling a rate of acidization, such that acidization can proceed slower at first and as the acid begins to increase subterranean formation permeability the acidity of the acidization fluid can be increased to further improve well performance. By allowing greater control of acidity in the downhole acidization fluid, various embodiments can reduce the use of excess acid, consequently reducing costs associated with purchasing acid, reducing acidization fluid recovery costs, reducing requirements for pumping equipment or power consumption, reducing non-acidic fluid requirements, or combinations thereof. Further embodiments can include mixing the acidic fluid with the non-acidic fluid downhole, below the BHA (bottom-hole assembly). Such embodiments can provide the benefit of reducing the amount of machinery, such as a mixer, piping, or valves, needed at a surface location. Further, various embodiments can use less overall fluid, such as acidic and non-acidic fluids, which can reduce recovery time during flow back or well testing. Such benefits can also reduce the costs associated with operations such as gas lifting.

Various embodiments can mitigate corrosion of pipes, such as tubing without a BHA, by directing acid to passages less susceptible to corrosion due to simultaneous pumping through multiple passages allowing the pipes to cool down the temperature of the well. Corrosion can be a determining factor in the length of time a subterranean formation can be subjected to acidization. In various embodiments, by mitigating or reducing corrosion effects, the length of time acidization can be performed on a subterranean formation is increased, so as to allow for an increase in permeability or performance of the subterranean formation. Further, in various embodiments, an amount of corrosion inhibitor used to mitigate corrosion of piping or tubing can be reduced. Benefits of such embodiments include mitigating environmental concerns, material cost reduction, simplifying the acidization process, or combination thereof.

Various embodiments can allow for greater acidization in high temperature wells. For example, pipe corrosion often increases with temperature, and thus high temperature wells can further limit the design or treatment time due to increased corrosion. Embodiments of the present disclosure include cooling of downhole fluid, increase acidization time, reduce corrosion effects, or combinations thereof. Various embodiments can include utilizing non-acidic fluid as an effective cooling fluid through a passage more susceptible to corrosion, while continuing to inject acid through a passage less susceptible to corrosion. Injecting both the non-acidic fluid and the acidic treatment fluid can provide greater downhole cooling capabilities than previous approaches that utilized only cooling fluid down one passage. Further, the present invention can use less cooling water, and therefore time and energy spent injecting and recovering the cooling fluid, than previous approaches that pumped water only down one passage to reduce downhole temperature.

In various embodiments, corrosion in high temperature wells can be mitigated by pumping acidic treatment fluid through a first passage at least partially simultaneously while pumping non-acidic fluid through a second passage. Such embodiments reduce corrosion as compared to traditional techniques that first involved pumping a large amount of cooling fluid down a high temperature well to reduce a downhole temperature prior to pumping acidic treatment fluid downhole. The previous techniques suffer from pipes heating back up when the acidic treatment fluid is pumped downhole; which can increase the amount of corrosion in areas of increased temperature. The present invention provides the benefit of continually pumping non-acidic fluid downhole, which serves as a cooling fluid, while the acidic treatment fluid is pumped downhole. Further, due to the present invention's ability to maintain a lower downhole temperature longer that previous approaches, the amount of time that acidic treatment fluid can be pumped downhole can be longer.

BRIEF DESCRIPTION OF THE FIGURES

In the drawings, which are not necessarily drawn to scale, like numerals describe substantially similar components throughout the several views. Like numerals having different letter suffixes represent different instances of substantially similar components. The drawings illustrate generally, by way of example, but not by way of limitation, various embodiments discussed in the present document.

FIG. 1 illustrates a subterranean treatment configuration, in accordance with various embodiments of the present disclosure;

FIG. 2 illustrates a coiled tubing subterranean treatment configuration, in accordance with various embodiments of the present disclosure;

FIG. 3 illustrates a subterranean treatment configuration and fluid flow, in accordance with various embodiments of the present disclosure; and

FIG. 4. illustrates a subterranean treatment configuration for circulating a fluid, in accordance with various embodiments of the present disclosure

DETAILED DESCRIPTION OF THE INVENTION

Reference will now be made in detail to certain embodiments of the disclosed subject matter, Examples of which are illustrated in part in the accompanying drawings. While the disclosed subject matter will be described in conjunction with the enumerated claims, it will be understood that the exemplified subject matter is not intended to limit the claims to the disclosed subject matter.

Values expressed in a range format should be interpreted in a flexible manner to include not only the numerical values explicitly recited as the limits of the range, but also to include all the individual numerical values or sub-ranges encompassed within that range as if each numerical value and sub-range is explicitly recited. For example, a range of “about 0.1% to about 5%” or “about 0.1% to 5%” should be interpreted to include not just about 0.1% to about 5%, but also the individual values (e.g., 1%, 2%, 3%, and 4%) and the sub-ranges (e.g., 0.1% to 0.5%, 1.1% to 2.2%, 3.3% to 4.4%) within the indicated range. The statement “about X to Y” has the same meaning as “about X to about Y,” unless indicated otherwise. Likewise, the statement “about X, Y, or about Z” has the same meaning as “about X, about Y, or about Z,” unless indicated otherwise.

In this document, the terms “a,” “an,” or “the” are used to include one or more than one unless the context clearly dictates otherwise. The term “or” is used to refer to a nonexclusive “or” unless otherwise indicated. In addition, it is to be understood that the phraseology or terminology employed herein, and not otherwise defined, is for the purpose of description only and not of limitation. Any use of section headings is intended to aid reading of the document and is not to be interpreted as limiting; information that is relevant to a section heading may occur within or outside of that particular section. Furthermore, all publications, patents, and patent documents referred to in this document are incorporated by reference herein in their entirety, as though individually incorporated by reference. In the event of inconsistent usages between this document and those documents so incorporated by reference, the usage in the incorporated reference should be considered supplementary to that of this document; for irreconcilable inconsistencies, the usage in this document controls.

In the methods of manufacturing described herein, the steps can be carried out in any order without departing from the principles of the invention, except when a temporal or operational sequence is explicitly recited. Furthermore, specified steps can be carried out concurrently unless explicit claim language recites that they be carried out separately. For example, a claimed step of doing X and a claimed step of doing Y can be conducted simultaneously within a single operation, and the resulting process will fall within the literal scope of the claimed process.

The term “about” as used herein can allow for a degree of variability in a value or range, for Example, within 10%, within 5%, or within 1% of a stated value or of a stated limit of a range.

The term “substantially” as used herein refers to a majority of, or mostly, as in at least about 50%, 60%, 70%, 80%, 90%, 95%, 96%, 97%, 98%, 99%, 99.5%, 99.9%, 99.99%, or at least about 99.999% or more.

The term “solvent” as used herein refers to a non-acidic liquid that can dissolve a solid, liquid, or gas. Nonlimiting examples of solvents are silicones, organic compounds, water, alcohols, ionic liquids, and supercritical fluids.

The term “room temperature” as used herein refers to a temperature of about 15° C. to 28° C.

The term “polymer” as used herein refers to a molecule having at least one repeating unit.

The term “copolymer” as used herein refers to a polymer that includes at least two different monomers. A copolymer can include any suitable number of monomers.

The term “downhole” as used herein refers to under the surface of the earth, such as a location within or fluidly connected to a wellbore.

As used herein, the term “subterranean material” or “subterranean formation” refers to any material under the surface of the earth, including under the surface of the bottom of the ocean. For example, a subterranean material can be any section of a wellbore, including any materials placed into the wellbore such as cement, casings, tubing, drill shafts, liners, bottom-hole assemblies, or screens. In various embodiments, a subterranean material can be any section of underground that can produce liquid or gaseous petroleum materials or water.

As used herein, the term “treatment fluid” refers to a fluid for treating a pipe, tubing, conduit, subterranean formation, fractures, perforations, or subterranean material.

As used herein, the term “diluent” refers to a diluting agent for the treatment fluid.

As used herein, the term “passage” refers to a conduit, such as tubing or piping, configured to provide fluid communication.

As used herein, the term “predetermined” refers to a previously established, calculated, determined, assayed, measured value or action.

As used herein, the term “fluid leak off” refers to a magnitude of pressure exerted on a subterranean formation that causes fluid to be forced into the subterranean formation, such as flowing into pore spaces, fractures, or cracks. Fluid leak off can be determined by a pressure integrity test (PIT) or a leak off test (LOT), in which injected fluid versus fluid pressure is plotted to determine the leak off point.

As used herein, the term “tube” can include any hollow structure designed to create a passage, such as a pipe.

As used herein, the term “bottom hole assembly” (BHA) refers to a lower portion of a drill, coiled tubing, or completion assembly including, but not limited to, a bit, a bit sub, a mud motor, stabilizers, a drill collar, a drill pipe, jarring devices, crossovers, jetting nozzles, packers, screens, pre-perforated tubing, or combinations thereof.

As used herein, the term “run-in-hole” refers to refers to transferring equipment, such as a drilling assembly, wireline logging tools, or casing, into the borehole.

As used herein, the term “casing” refers to a large diameter pipe that is assembled and inserted into a drilled borehole. A casing can be held in place by cement or can be uncemented.

As used herein, the term “acidic” refers to any material, organic or inorganic, with a pH of 7 or less.

As used herein, the term “non-acidic” refers to any material, organic or inorganic, with a pH of 7 or greater.

As used herein, the term “coiled tubing” refers to a continuous string of tubing deployed into a well from a reel on a surface for non-permanent interaction with a wellbore.

As used herein, the term “liner” refers to a casing segment that does not extend to the surface but is attached to a section of casing downhole. Liner can be cemented or uncemented to the casing.

Subterranean Treatment Configurations

FIG. 1 illustrates an exemplary subterranean treatment configuration 10. Although FIG. 1 illustrates a conventional vertical subterranean treatment, embodiments are not so limited. Subterranean treatment configuration 10 can include horizontal wells, slant wells, directional wells, high temperature wells, high pressure wells, high-temperature-high-pressure wells (HTHP), or combinations thereof. High temperature wells can include wells with a downhole or bottomhole temperature of about 200 degrees Fahrenheit (° F.) to about 60° F., 300° F., 350° F., 400° F., 450° F., or about 500° F. or more. HTHP wells can present a number of factors that make them more difficult to operate than, for example, conventional wells. For example, high temperature wells can increase the rate of corrosion on casing, tubing, piping, or bottomhole assemblies (BHA). In various embodiments, the borehole can be at least partially or fully cased.

Subterranean treatment configuration 10 can include a first passage 2, including tubing, or a second passage 4, such as an annulus between an outer tube wall 5 and a casing 24 or a borehole 26. An exemplary BHA 6 is illustrated downhole in FIG. 1. The BHA 6 can include, but is not limited to, a lower portion of a drill, coiled tubing, or completion assembly including, but not limited to, a bit, a bit sub, a mud motor, a stabilizer, a drill collar, a drill pipe, a jarring device, a crossover, packer, a jetting nozzle, a screen, preperforated tubing, or combinations thereof. Equipment included in the BHA 6 can be susceptible to corrosion, such as from acid. As illustrated in FIG. 1, subterranean treatment configuration 10 can provide access from a surface 14 to a subterranean formation 8, which can contain hydrocarbons. Subterranean formation 8 can include a number of fractures or wormholes 12, such as those naturally occurring or produced by machine, fracturing, chemical treatment, or a combination thereof. A wormhole 12 can include an empty channel capable of penetrating inches or feet into the subterranean formation 8. Wormholes 12 can be formed by acidization which can dissolve or erode, for example, limestone, carbonate, dolomite, or combinations thereof.

FIG. 2 illustrates a subterranean treatment configuration 20 that can include a coiled tubing 22. As illustrated in FIG. 2, coiled tubing 22 is disposed in a non-coiled tube 23, such as completion or production tubing. Further embodiments can include the coiled tubing 22 inside the casing 24 alone and no non-coiled tubing 23, such as in a passage 30. As illustrated in FIG. 2, coiled tubing 22 can define the first passage 27, such as within the coiled tubing. The second passage can include at least one of 28 or 30, both of which are disposed between the first passage way 27 and the casing 24 or borehole 26. In various embodiments, the borehole 26 can be at least partially or full cased.

Coiled tubing can include metal piping. Coiled tubing can be used in various manners for interventions or for wellbore or reservoir evaluation. Interventions can include any operation that can alter the state or geometry of the well, provide well diagnostics, or manage the production of the well, such as by use of various coiled tubing manipulations of downhole devices or introduction of devices to alter or control the well. Evaluation is accomplished when the coiled tubing is used to lower measurement devices into the well for the purposes of collecting data for wellbore or reservoir evaluation. As shown in FIG. 2, the coiled tubing 22 and non-coiled tubing 23 can each include a BHA 6-1, 6-2, respectively.

Method of Treating a Subterranean Formation

As shown in FIG. 3, a subterranean treatment configuration 30 can include injecting a treatment fluid 32 through a first passage 2 while at least partially simultaneously injecting a non-acidic fluid 34, such as a diluent, through a second passage 4. The subterranean formation 8 can be treated prior to run-in-hole completion. The subterranean formation 8 can be treated after a borehole 26 has been drilled through the formation while it is in an open hole state before being completed, or after a pre-slotted, pre-perforated, or pre-drilled liner has been installed in the formation. Further, the subterranean formation 8 can be treated after a casing 24 has been installed and cemented in the formation and perforated. In an open hole state, the introduction of the treatment fluid 32 can react with the formation 8 directly to remove near-wellbore impediment, such that the treatment fluid 32 can flow in the formation 8. In a pre-slotted, pre-perforated, or pre-drilled liner completion, the treatment fluid 32 can flow out through the slots, perforations, or drilled holes, and act in the same way to stimulate the formation 8. For a cased 24 hole completion, perforating the casing 24 can include one or more holes created in the casing 24 or liner of well to connect it to the reservoir so that the treatment fluid 32 can stimulate the formation 8. Further embodiments can include methods of treating a subterranean formation 8, so as to stimulate well production or unclog perforations in the subterranean formation. In various embodiments, the treatment fluid 32 can include an acid or a solvent. An acid can include hydrochloric acid (HCl), acetic acid, hydrofluoric acid (HF), formic acid, or a combination thereof. For example, the treatment fluid 32 can include a concentration of at least about 1% HCl, 2% HCl, 3% HCl, 4% HCl, 5% HCl, 7% HCl, 10% HCl, 12% HCl, 15% HCl, 17% HCl, 20% HCl, 25% HCl, 30% HCl, or about 40% HCl, or more. Further examples includes blends of HCl and HF, such as HCl concentrations of about 15% or less and HF concentrations of about 5% of less. Non-limiting examples of HCl and HF treatment fluid includes about 13.5% HCl: 1.5% HF, 12% HCl: 3% HF, 9% HCl: 1% HF, or 6% HCl: 1.5% HF, where percentage of HCl and HF is weight percent of the treatment fluid 32. Further, the treatment fluid 32 can include HCl and an organic acid, such as acetic acid, formic acid, or citric acid. In such embodiments, the organic acid can be from about 8% to about 25% of the weight of the treatment fluid. In an embodiment, the treatment fluid 32 can include a solvent. The solvent can be any suitable solvent, such as water, silicones, organic compounds, alcohols, ionic liquids, supercritical fluids, or combinations thereof.

In various embodiments, the treatment fluid 32 can include a corrosion inhibitor. A corrosion inhibitor can include any chemical compound that, when added to a fluid, decreases the corrosion rate of a material. For example, a corrosion inhibitor can include a water-dispersible amine, a persistent filming amine, a corrosion inhibitor from saturated salt water-based muds, phosphorus-based, or combinations therein. Various embodiments of the present disclosure can reduce the amount of corrosion inhibitor needed for the subterranean treatment configuration 30, such as a high temperature, high pressure, or HTHP operation, as compared to previous approaches. A non-acidic fluid 34 can include water, brine, diesel, solvent, base oil, emulsifiers, foaming agents, gas internal phase foams, or combinations thereof. In various embodiments, the acidic treatment fluid 32 can be injected through the first passage 2 less than, substantially equal to, or greater than a fracture pressure of the subterranean formation 8. That is, the present invention can supply the acidic treatment fluid 32 in a matrix acidizing environment (e.g., at or below fracturing pressure to prevent fracturing), a closed fracture acidizing environment (e.g., at or below fracturing pressure, intended to provide acid to existing closed fractures), or an acid fracturing environment (e.g., at or above fracturing pressure to create new fractures).

An acidization or comingled fluid 36 can include a mixture of the treatment fluid 32 and the non-acidic fluid 34. The acidization fluid 36 can contact a subterranean material or formation 8 downhole. In an embodiment, comingling of the fluids can include forming a foamed or emulsified system. The downhole contacting of the comingled fluid 36 with the subterranean formation 8 can be any suitable contacting. In various embodiments, the contacting can include contacting subterranean material 8 that is in or proximate to a production zone. The treatment fluid 32 and non-acidic fluid 34 can mix downhole of the BHA 6, within the subterranean formation 8, at a bottomhole location of the borehole, or a combination thereof. In various embodiments, an injection rate of at least one of the treatment fluid 32 and the non-acidic fluid 34 can be regulated to cause a predetermined concentration of the acidization fluid 36 in the mixture downhole. For example, a decrease in the first flow rate of the treatment fluid 32 or an increase of the second flow rate of the non-acidic fluid 34 can cause the concentration of acidization fluid 36 in the mixture downhole to decrease. The acidization fluid 36 can be about 0.01% to about 40% acid concentration. The acidization fluid 36 can acidize the subterranean material, so as to increase permeability or increase well production. In various embodiments, the acidization can take place for a predetermined time. Certain embodiments can provide acidization times longer than previous approaches, such as with high temperature wells. In some embodiments, the multiple passage configuration of the present disclosure can provide greater temperature change downhole, decrease corrosion of equipment, or a combination thereof.

In various embodiments, the method of treating a subterranean formation 8 can include spotting a low concentration acid pill across a treatment interval to clean the perforations so as to dissolve debris or acid soluble material. For example, the pill can be spotted prior to injecting fluid through the first or second passage. A pill is a relatively small quantity (e.g., less than about 500 bbl, or less than about 200 bbl) of treatment fluid.

In various embodiments, the method of treating a subterranean formation can include monitoring a downhole pressure of the comingled mixture 36. The pressure can be monitored continuously or at designated intervals. Further, the injection rate of at least one of the treatment fluid 32 and the non-acidic fluid 34 can be increased when the monitored pressure is below a threshold value. For example, a below threshold value of the monitored pressure can indicated fluid leak off, acidization, increase permeability, or combinations thereof.

In various embodiments, the first passage 2 of FIG. 3 can include coiled tubing, as described in connection with FIG. 2. In some embodiments, the second passage 4 of FIG. 3 can comprise a space between the coiled tubing and the borehole 26 or casing 24. In still further embodiments, the coiled tubing can be disposed in non-coiled tubing, wherein the second passage comprises a space between the coiled tubing and the non-coiled tubing, or a space between the non-coiled tubing and the borehole 26 or casing 24, or a combination thereof. Various embodiments include, injecting non-acidic fluid 34 in a space or annulus between the non-coiled tubing and the borehole 26 or casing 24. Such embodiments can provide the benefit of greater temperature control or greater control in varying the treatment fluid concentration in the comingled fluids downhole.

As illustrated in FIG. 4, prior to the acidization or comingled fluid (e.g., 36, FIG. 3) contacts the subterranean formation (e.g., 8, FIG. 3), the method of treating a subterranean formation 8 can include circulating 40 a first non-acidic fluid 48 in the borehole 26 by injecting 42 into a first passage 2, flowing 44 out of the first passage 2 at such place where that passage connects to a second passage 4, and then out 45 of the well through the second passage 4. Further, the method can include measuring a temperature of the circulating first non-acidic fluid 48 at a surface 14. The circulating of the first non-acidic fluid 48 can result in a decrease in an initial temperature downhole. However, following such circulation the temperature of the wellbore typically increases quickly once circulation is ceased. The temperature of the recirculated first non-acidic fluid 48 can be used to determine flow rates of the non-acidic fluid, treatment fluid, or a combination thereof. For example, the one or more flow rates can be determined by a desired temperature difference of the first non-acidic fluid 48, such as the difference between an initial downhole temperature and the temperature of the first non-acidic fluid 48 when it returns. The circulation of the first non-acidic fluid 48 through the first passage 2 can be stopped, such that the treatment fluid (e.g., 32, FIG. 3) can be injected at a first flow rate through the first passage 2 while a second non-acidic fluid (e.g., 34, FIG. 3) can be injected at a second flow rate through the second passage 4. In various embodiments, the circulated first non-acidic treatment fluid 48 can be substantially similar to the second non-acidic treatment fluid (e.g., 34, FIG. 3).

Method for Stimulating a Well

A method for stimulating a well can include injecting a first non-acidic fluid (e.g., 48, FIG. 4) through a first passage (e.g., 2, FIG. 3) comprising tubing. The method can include reducing the injecting, such as an injection rate, of the first non-acidic fluid through the first passage. Further, the method can include injecting a second non-acidic fluid (e.g., 34, FIG. 3) through a second passage (e.g., 4, FIG. 3) comprising a space between the tubing and a borehole or casing (e.g., 26 and 24, FIG. 3, respectively). In various embodiments, the reducing of the first non-acidic fluid and the injecting of the second non-acidic fluid can be done at least partially simultaneously. The injection of the first non-acidic fluid through the first passage can be stopped while, at least partially simultaneously, an acidic treatment fluid (e.g., 32, FIG. 3) can be injected through the first passage. In an embodiment, the first non-acidic fluid can be the same fluid as the second non-acidic fluid. For example, returning to FIG. 3, the injection of the first non-acidic fluid has ceased, such that the treatment fluid can be in the first passage and the second non-acidic treatment fluid is being injected in the second passage.

The acidic treatment fluid can include any acid described herein. In an embodiment, the combined flow rate of the second non-acidic fluid and acidic treatment fluid can be less than, about equal to, or greater than the initial flow rate of the first non-acidic fluid. The second non-acidic fluid and acidic treatment fluid can comingle at a downhole location in the borehole, as described herein, to form a comingled fluid configured to contact the subterranean formation. A concentration of the acidic treatment fluid in the comingled fluid can be varied, such as by varying a concentration of acid in the acidic treatment fluid, adjusting the flow rate of at least one of the acidic treatment fluid and second non-acidic fluid, or combinations thereof.

In various embodiments, the flow rate of at least one of the acidic treatment fluid and the second non-acidic fluid can be increased upon detecting acidization, increased fluid leak off, or both. Acidization or fluid leak off can be detected by monitoring a surface or downhole pressure. For example, a decrease in downhole pressure can indicated acidization or fluid leak off. Further, the concentration of acidic treatment fluid can be increased in the comingled fluids upon detecting acidization or fluid leak off.

The method of stimulating a well can include reducing an initial downhole temperature, such as a bottomhole static temperature, of at least the first passage, such as by adjusting the flow rate of at least one of the second non-acidic fluid or the acidic treatment fluid. For example, increasing the flow rate of the second non-acidic fluid can increase heat transfer from the tubing of the first passage to the second non-acidic fluid. The initial downhole temperature of the first passage can be at least about 100° F., 150° F., 200° F., 250° F., 300° F., 350° F., 400° F., 450° F., or about 500° F. The initial downhole temperature of the first passage can be reduced by about 1%, 5%, 10%, 15%, 20%, 30%, 40%, 50%, 60%, 70%, 75%, or about 80%. Such examples can provide the benefit of mitigating or reducing corrosion of drilling or completion equipment, stabilizing well stimulation conditions, or both.

In various embodiments, the tubing can comprise coiled tubing, as described herein. In some embodiments, the second passage can comprise a space between the coiled tubing and the borehole or casing. In still further embodiments, the coiled tubing can be disposed in non-coiled tubing, wherein the second passage comprises a space between the coiled tubing and the non-coiled tubing, or a space between the non-coiled tubing and the borehole or casing, or a combination thereof. Various embodiments include, injecting non-acidic fluid in a space or annulus between the non-coiled tubing and the borehole or casing. Such embodiments can provide the benefit of greater temperature control or greater control in varying the treatment fluid concentration in the comingled fluids downhole.

In various embodiments, the method of treating a subterranean formation can include spotting a low concentration acid pill across a treatment interval to clean the perforations so as to dissolve debris or acid soluble material. For example, the pill can be spotted prior to injecting fluid through the first or second passage. A pill is a relatively small quantity (e.g., less than about 500 bbl, or less than about 200 bbl) of treatment fluid.

Acidization of a Subterranean Formation

A method of acidization of a subterranean formation can include injecting the first non-acidic fluid through a tube disposed in a borehole. The injection of the first non-acidic fluid through the tube can be reduced while, at least partially simultaneously, injecting a second non-acidic fluid through an annulus disposed between the tube and the borehole or casing, and the acidic treatment fluid can be injected through the tube with the first non-acidic fluid. The flow rate of the second non-acidic fluid can be less than, about equal to, or greater than the flow rate of the first non-acidic fluid. The injection of the first non-acidic fluid can be stopped and acidic treatment fluid can be injected through the tube at a rate less than, about equal to, or greater than the flow rate of the second non-acidic fluid. The fluids injected through the tube and annuls can be comingled at a first downhole location, such that the comingled fluids can contact the subterranean formation downhole. The first downhole location can include any location along the borehole below the surface to the bottomhole. The comingled fluids can contact the subterranean formation downhole to acidize the subterranean formation. The method of acidization can include increasing at least one of an acidic concentration or injecting rate of the acidic treatment fluid upon detecting acidization, increased fluid leak off, or both. For Example, increasing the acidic concentration of the acidic treatment fluid can further permeate or acidize the subterranean formation. At least a portion of the comingled fluids can be recovered as spent fluid from a downhole location to the surface, a reservoir, or both. Spent fluid can include fluid containing acid that has contacted the subterranean formation or other material such that a chemical reaction has taken place to change the chemistry of the initial fluid. For example, the spent fluid can be a fraction of the acidity of the comingled fluid or contain some dissolved material, such as limestone or carbonate.

The method of acidization can include varying the flow rate of at least one of the non-acidic fluid and the acidic treatment fluid to reduce a BHA temperature. For example, the BHA temperature can be reduced to a temperature to mitigate corrosion damage.

In various embodiments, the tubing can comprise coiled tubing, as described herein. In some embodiments, the second passage can comprise a space between the coiled tubing and the borehole or casing. In still further embodiments, the coiled tubing can be disposed in non-coiled tubing, wherein the second passage comprises a space between the coiled tubing and the non-coiled tubing, or a space between the non-coiled tubing and the borehole or casing, or a combination thereof. Various embodiments include, injecting non-acidic fluid in a space or annulus between the non-coiled tubing and the borehole or casing. Such embodiments can provide the benefit of greater temperature control or greater control in varying the treatment fluid concentration in the comingled fluids downhole.

In various embodiments, the method of treating a subterranean formation can include spotting a low concentration acid pill across a treatment interval to clean the perforations so as to dissolve debris or acid soluble material. For example, the pill can be spotted prior to injecting fluid through the first or second passage. A pill is a relatively small quantity (e.g., less than about 500 bbl, or less than about 200 bbl) of treatment fluid.

EXAMPLES

The present invention can be better understood by reference to the following Examples which are offered by way of illustration. The present invention is not limited to the Examples given herein.

Example 1

Hypothetical Example

FIG. 1 illustrates a configuration for treating a well. The following conditions exist:

• • Bottomhole temperature is greater than 400° F.
  • The well includes a perforated casing
  • The subterranean formation includes carbonate with an HCl solubility of greater than 85%
  • Annulus to tubing volume ratio is 1:1

The following actions are performed:

• • Circulating water out at least one of the tubing or annulus
  • Recording the temperature of the circulated water at the surface
  • Spotting a low concentration acid pill across treatment interval to clean the perforated casing and to dissolve debris or acid soluble material
  • Establishing initial injection by pumping 4 barrels per minute (BPM) of water through the tubing, recording the temperature and pressure
  • Reducing the injection rate of water to 2 BPM through the tubing
  • Injecting 2 BPM of water through the annulus
  • Switching to 2 BPM 20% HCl treatment fluid through the tubing

The terms and expressions which have been employed are used as terms of description and not of limitation, and there is no intention that in the use of such terms and expressions of excluding any equivalents of the features shown and described or portions thereof, but it is recognized that various modifications are possible within the scope of the invention claimed. Thus, it should be understood that although the present invention has been specifically disclosed by preferred embodiments and optional features, modification and variation of the concepts herein disclosed may be resorted to by those of ordinary skill in the art, and that such modifications and variations are considered to be within the scope of this invention as defined by the appended claims.

Additional Embodiments

The present invention provides for the following exemplary embodiments, the numbering of which is not to be construed as designating levels of importance:

Embodiment 1 provides a method of treating a subterranean formation, the method comprising: injecting a treatment fluid comprising at least one of acid and solvent through a first passage while at least partially simultaneously injecting a non-acidic fluid through a second passage; and contacting a mixture of at least the treatment fluid and the non-acidic fluid with a subterranean material downhole, wherein the first passage comprises tubing disposed in a borehole, wherein the second passage comprises a space between the tubing and the borehole.

Embodiment 2 provides the method of Embodiment 1, further comprising: circulating the non-acidic fluid through the first passage toward the subterranean material downhole; allowing the non-acidic fluid to flow up from the subterranean material downhole, prior to injecting the treatment fluid; measuring a temperature of the circulating non-acidic fluid at a surface; and stopping the circulation of the non-acidic fluid.

Embodiment 3 provides the method of at least one of or any combination of Embodiments 1-2, wherein the treatment fluid is injected through the first passage at flow rate about equal to a flow rate of the non-acidic fluid through the second passage.

Embodiment 4 provides the method of at least one of or any combination of Embodiments 1-3, further comprising spotting an acid pill over at least a portion of the treatment or perforated interval in the borehole.

Embodiment 5 provides the method of at least one of or any combination of Embodiments 1-4, further comprising monitoring a downhole pressure of the mixture.

Embodiment 6 provides the method of at least one of or any combination of Embodiments 1-5, further comprising increasing an injection rate of at least one of the treatment fluid and the non-acidic fluid when the monitored pressure is below a threshold value.

Embodiment 7 provides the method of at least one of or any combination of Embodiments 1-6, further comprising regulating an injection rate of at least one of the treatment fluid and the non-acidic fluid to cause a predetermined concentration of the treatment fluid in the mixture downhole.

Embodiment 8 provides the method of at least one of or any combination of Embodiments 1-7, wherein the treatment fluid comprises hydrochloric (HCl) acid, acetic acid, citric acid, hydrofluoric acid, formic acid, or combinations thereof.

Embodiment 9 provides the method of at least one of or any combination of Embodiments 1-8, wherein the treatment fluid is at least about 15% HCl.

Embodiment 10 provides the method of at least one of or any combination of Embodiments 1-9, wherein treatment fluid further comprises a corrosion inhibitor.

Embodiment 11 provides the method of at least one of or any combination of Embodiments 1-10, wherein the non-acidic fluid comprises water, brine, diesel, solvent, base oil, emulsifiers, foaming agents, gas internal phase foams, or combinations thereof.

Embodiment 12 provides the method of at least one of or any combination of Embodiments 1-11, further comprising acidizing the subterranean material with a mixture of the treatment fluid and the non-acidic fluid for a predetermined time.

Embodiment 13 provides the method of at least one of or any combination of Embodiments 1-12, wherein the tubing comprises coiled tubing, wherein the second passage comprises a space between the coiled tubing and the borehole or casing.

Embodiment 14 provides the method of at least one of or any combination of Embodiments 1-13, wherein the coiled tubing is disposed in non-coiled tubing, wherein the second passage comprises a space either between the coiled tubing and the non-coiled tubing or the non-coiled tubing and the borehole or casing.

Embodiment 15 provides the method of at least one of or any combination of Embodiments 1-14, wherein the method is a method of at least one of stimulating well production and unclogging perforations in the subterranean material.

Embodiment 16 provides a method of stimulating a well, the method comprising: injecting a first non-acidic fluid through a first passage comprising tubing disposed in a borehole; reducing the injecting of the first non-acidic fluid through the first passage; injecting a second non-acidic fluid through a second passage comprising a space between the tubing and a borehole; stopping the injecting of the first non-acidic fluid through the first passage, while at least partially simultaneously injecting an acidic treatment fluid through the first passage; comingling the second non-acidic fluid of the second passage and the acidic treatment fluid of the first passage at a downhole location in the borehole; contacting the comingled fluid with a subterranean material of the well; and varying a concentration of the acidic treatment fluid in the comingled fluids.

Embodiment 17 provides the method of Embodiment 16, wherein varying the concentration comprises varying a concentration of the acidic treatment fluid injected through the first passage.

Embodiment 18 provides the method of at least one of or any combination of Embodiments 16-17, wherein varying the concentration comprises adjusting a flow rate of at least one of the second non-acidic fluid and the acidic treatment fluid.

Embodiment 19 provides the method of at least one of or any combination of Embodiments 16-18, wherein the first non-acidic fluid and the second non-acidic fluid are substantially the same composition.

Embodiment 20 provides the method of at least one of or any combination of Embodiments 16-19, further comprising at least one of increasing a flow rate of the acidic treatment fluid and decreasing the flow rate of the second non-acidic fluid upon detecting acidization, increased fluid leak off, or both.

Embodiment 21 provides the method of at least one of or any combination of Embodiments 16-20, further comprising increasing a treatment fluid concentration of the comingled fluids upon detecting acidization, increased fluid leak off, or both.

Embodiment 22 provides the method of at least one of or any combination of Embodiments 16-21, further comprising reducing a downhole temperature of at least the first passage by increasing at least one of a flow rate of the acidic treatment fluid and a flow rate of the second non-acidic fluid.

Embodiment 23 provides the method of at least one of or any combination of Embodiments 16-22, further comprising adjusting a flow rate of at least one of the second non-acidic fluid or the acidic treatment fluid to reduce the downhole temperature.

Embodiment 24 provides the method of at least one of or any combination of Embodiments 16-23, wherein the method is a method for stimulating a high temperature well with a downhole temperature of at least about 200 to about 500 degrees Fahrenheit.

Embodiment 25 provides the method of at least one of or any combination of Embodiments 16-24, further comprising spotting an acid pill over at least a portion of the treatment or perforated interval in the borehole.

Embodiment 26 provides a method of acidization of a subterranean formation, the method comprising: injecting a first non-acidic fluid through first passage comprising a tube disposed in a borehole; reducing the injecting of the first non-acidic fluid through the tube, while at least partially simultaneously injecting a second non-acidic fluid through a second passage disposed between the tube and the borehole; stopping the injecting of the first non-acidic fluid through the tube while at least partially simultaneously injecting acidic treatment fluid through the tube; comingling the second non-acidic fluid and the acidic treatment fluid at a first downhole location; contacting the comingled fluid with the subterranean formation downhole; increasing at least one of an acidic concentration or an injection rate of the acidic treatment fluid upon detecting acidization, increased fluid leak off, or both; and pumping at least a portion of the comingled fluids from a second downhole location to a surface.

Embodiment 27 provides the method of Embodiment 26, wherein the tube comprises a coiled tube, wherein the second passage comprises a space between the coiled tubing and the borehole.

Embodiment 28 provides the method of at least one of or any combination of Embodiments 26-27, wherein the coiled tubing is disposed in a non-coiled tube, wherein the first passage comprises a space within the coiled tubing, and wherein the second passage comprises at least one of a space between the coiled tubing and the non-coiled tube and a space between the non-coiled tube and the borehole.

Embodiment 29 provides the method of at least one of or any combination of Embodiments 26-28, further comprising injecting the acidic treatment fluid at a rate at least equivalent to an injection rate of the second non-acidic fluid.

Embodiment 30 provides the method of at least one of or any combination of Embodiments 26-29, further comprising varying at least one of the injection rate of the acidic treatment fluid and an injection rate of the second non-acidic fluid to reduce a bottom-hole assembly temperature.

Embodiment 31 provides the method of at least one of or any combination of Embodiments 26-30, further comprising spotting an acid pill over at least a portion of the treatment or perforated interval in the borehole.

Embodiment 32 provides the method of any one or any combination of Embodiments 1-31 optionally configured such that all elements or options recited are available to use or select from.

Claims

1. A method of treating a subterranean formation, the method comprising:

injecting a treatment fluid comprising at least one of acid and solvent through a first passage while at least partially simultaneously injecting a non-acidic fluid through a second passage; and

contacting a mixture of at least the treatment fluid and the non-acidic fluid with a subterranean material downhole,

wherein the first passage comprises tubing disposed in a borehole, wherein the second passage comprises a space between the tubing and the borehole.

2. The method of claim 1, further comprising:

circulating the non-acidic fluid through the first passage toward the subterranean material downhole;

allowing the non-acidic fluid to flow up from the subterranean material downhole, prior to injecting the treatment fluid;

measuring a temperature of the circulating non-acidic fluid at a surface; and

stopping the circulation of the non-acidic fluid.

3. The method of claim 1, wherein the treatment fluid is injected through the first passage at flow rate about equal to a flow rate of the non-acidic fluid through the second passage.

4. The method of claim 1, further comprising monitoring a downhole pressure of the mixture.

5. The method of claim 4, further comprising increasing an injection rate of at least one of the treatment fluid and the non-acidic fluid when the monitored pressure is below a threshold value.

6. The method of claim 1, further comprising regulating an injection rate of at least one of the treatment fluid and the non-acidic fluid to cause a predetermined concentration of the treatment fluid in the mixture downhole.

7. The method of claim 1, wherein the treatment fluid comprises hydrochloric (HCl) acid, acetic acid, citric acid, hydrofluoric acid, formic acid, or combinations thereof.

8. The method of claim 1, wherein the treatment fluid is at least about 15% HCl.

9. The method of claim 1, wherein the non-acidic fluid comprises water, brine, diesel, solvent, base oil, emulsifiers, foaming agents, gas internal phase foams, or combinations thereof.

10. The method of claim 1, wherein the tubing comprises coiled tubing, wherein the second passage comprises a space between the coiled tubing and the borehole.

11. The method of claim 10, wherein the coiled tubing is disposed in non-coiled tubing, wherein the second passage comprises a space between the non-coiled tubing and the borehole.

12. A method of stimulating a well, the method comprising:

injecting a first non-acidic fluid through a first passage comprising tubing disposed in a borehole;

reducing the injecting of the first non-acidic fluid through the first passage;

injecting a second non-acidic fluid through a second passage comprising a space between the tubing and a borehole;

stopping the injecting of the first non-acidic fluid through the first passage, while at least partially simultaneously injecting an acidic treatment fluid through the first passage;

comingling the second non-acidic fluid of the second passage and the acidic treatment fluid of the first passage at a downhole location in the borehole;

contacting the comingled fluid with a subterranean material of the well; and

varying a concentration of the acidic treatment fluid in the comingled fluids.

13. The method of claim 12, wherein varying the concentration comprises varying a concentration of the acidic treatment fluid injected through the first passage.

14. The method of claim 12, wherein varying the concentration comprises adjusting a flow rate of at least one of the second non-acidic fluid and the acidic treatment fluid.

15. The method of claim 12, wherein the first non-acidic fluid and the second non-acidic fluid are substantially the same composition.

16. The method of claim 12, further comprising reducing a downhole temperature of at least the first passage by increasing at least one of a flow rate of the acidic treatment fluid and a flow rate of the second non-acidic fluid.

17. The method of claim 16, further comprising adjusting a flow rate of at least one of the second non-acidic fluid or the acidic treatment fluid to reduce the downhole temperature.

18. A method of acidization of a subterranean formation, the method comprising:

injecting a first non-acidic fluid through first passage comprising a tube disposed in a borehole;

reducing the injecting of the first non-acidic fluid through the tube, while at least partially simultaneously injecting a second non-acidic fluid through a second passage disposed between the tube and the borehole;

stopping the injecting of the first non-acidic fluid through the tube while at least partially simultaneously injecting acidic treatment fluid through the tube;

comingling the second non-acidic fluid and the acidic treatment fluid at a first downhole location;

contacting the comingled fluid with the subterranean formation downhole;

increasing at least one of an acidic concentration or an injection rate of the acidic treatment fluid upon detecting acidization, increased fluid leak off, or both; and

pumping at least a portion of the comingled fluids from a second downhole location to a surface.

19. The method of claim 18, wherein the tube comprises a coiled tube, wherein the second passage comprises a space between the coiled tubing and the borehole.

20. The method of claim 19, wherein the coiled tubing is disposed in a non-coiled tube, wherein the first passage comprises a space within the coiled tubing, and wherein the second passage comprises at least one of a space between the coiled tubing and the non-coiled tube and a space between the non-coiled tube and the borehole.